Kathleen Lally – VP, IR Ralph Izzo – Chairman, President and CEO Caroline Dorsa – EVP and CFO

Daniel Eggers – Credit Suisse Greg Gordon – Morgan Stanley Paul Patterson – Glenrock Associates Paul Fremont – Jefferies Jonathan Arnold – Deutsche Bank Steve Fleishman – Merrill Lynch Neel Mitra – Simmons & Company Marc De Croisset – FBR Capital Markets Ashar Khan – Visium Asset Management Leslie Rich – JPMorgan Michael Lapides – Goldman Sachs

Thank you, operator. Good morning.

Thank you all for participating in PSEG’s call. As you are aware, we released our third quarter 2010 earnings statements earlier today.

They are also the release and the attachments are posted on our website at www.pseg.com in the Investors section. We also have posted a series of slides that detail our operating results by company for the quarter.

Our 10-Q for the period ended September 30th, 2010 it will be filed shortly. I’m not going to read the full disclaimer statement or the comments that we have on the difference between operating earnings and GAAP results.

However, as you know the release and other matters that we will discuss in today’s call contain forward-looking statements and estimates that are subject to various risks and uncertainties. And although we may elect to update forward-looking statements from time-to-time, we specifically disclaim any obligation to do so even if our estimate changes unless we are absolutely required to do so obviously.

Our release also contains adjusted non-GAAP operating earnings. Please refer to our 8-K today containing the earnings statement and other filings for a discussion of the factors that may cause results to differ from management’s projections, forecasts and expectations, and for a reconciliation of those operating earnings to GAAP results.

I’m now going to turn the call over to Ralph Izzo, Chairman, President, and Chief Executive Officer of Public Service Enterprise Group. Joining Ralph on the call is Caroline Dorsa, Executive Vice President and Chief Financial Officer.

At the conclusion of their remarks, there will be time for your questions, and we do ask that you limit yourself to a one question and one follow-up. We hope that there will be plenty of time for all of your questions today.

With that, I’ll turn the call over to Ralph.

Thank you, Kathleen. Good morning and thank you everyone for joining us today.

Earlier this morning, we reported operating earnings for the third quarter of 2010 of $1.06 per share compared with operating earnings of $0.92 per share in 2009’s third quarter. Overall, operating earnings benefited from strong weather related demand.

New Jersey experienced the hottest summer on record this year. This stands in contrast to last year’s very cool weather conditions.

For the past three quarters, we’ve been saying the economy appears to have stabilized, well that story remains unchanged. The signals coming from employment levels and housing indicate the economy may have bottomed, but as of yet no signs of a significant recovery have appeared.

Company execution was strong in the quarter. Our fossil generating units in particular were available to respond to the increase in demand and our employees continue to support our results through their constant focus on operating efficiency and cost control.

Capital commitments are being met as well. PSEG Power is in the midst of testing the backend technology installed on the Hudson and Mercer Coal Stations.

These units are expected to meet stringent environmental requirements for sulfur, mercury, nitrous oxides in particular. PSEG is in the midst of a $700 million capital program that will produce a 160 megawatts of solar energy.

PSEG Energy Holdings has completed the installation of 29 megawatts of solar capacity in New Jersey, Ohio and Florida, and is reviewing additional PPA supported solar investments. These are but a few examples.

Caroline will have more details on the capital program later on. We’re moving forward with PSEG substantial capital investment and transmission.

The update we’re providing you today of PSEG planned capital outlays takes into account the announced reductions in distribution related spending, the delay in construction of the Susquehanna-Roseland transmission line, and PJM’s recently approved reconfiguration of the Branchburg-Roseland-Hudson transmission line. The net result will be a capital program yielding annual growth in the utilities rate base of 9.5% per year over 2010 to 2013 with transmission continuing its role as our most significant area of investment.

We continue to reduce our financial risk and maintain our focus on core markets. PSEG Energy Holdings successfully terminated another two cross-border leases during the quarter.

Over the past two years, the successful termination of 17 leases has reduced the Holdings’ potential tax liability by $1 billion with one lease remaining in the cross-border lease portfolio. PSEG Power announced during the quarter that it is exploring the sale of its Texas gas-fired combined cycle generating capacity.

If successful, we expect the sale to close during the first quarter of 2011. We’ve been saying that we need us to get bigger in Texas or get out, and we have not found appropriate opportunities to grow in that market.

The sale of the Texas assets will reduce the overall size of the portfolio by 2,000 megawatts, but it will improve returns on the portfolio and keep the focus squarely on the markets and assets with the highest value. Our results for the quarter and year-to-date continued to support our full-year operating earnings guidance of $3 to $3.25 per share.

We experienced the benefits of an improvement in weather related demand on pricing this summer, which continues to demonstrate the location of value of our assets. Say it another way, basis returned with demand albeit weather driven.

The power markets, however, remain challenging. The price of natural gas has fallen faster and further than implied by the forward curve.

Our reported results continue to benefit from higher priced legacy hedges, which was scheduled to expire in 2011 and 2012. As you know, the relatively high imbedded cost of energy in our hedges under the basic generation service, as we refer to it as BGS contract versus today’s market prices led to the entry of new retail suppliers into the marketplace.

An increase in market penetration by retail supplies accelerates the impact on margins that would happen eventually from the reset of the BGS contract prices. We’re working hard to address the market challenges, we’re focused on reducing O&M without sacrificing reliability, our financial condition remains strong, the markets we serve remain constrained, and we’re well positioned for potential new EPA Regulations.

Our efforts to build an organization that focuses on maximizing efficiency, promoting renewables and building a sustainable energy strategy have not gone unnoticed. PSEG was added to the Dow Jones Sustainability Role Index for the first time this year having been on the national index for the prior two years.

And PSEG was recognized by the Carbon Disclosure Project for its efforts to reduce emissions and mitigate the risks of climate change. We aren’t immune to declining market prices, but we’re well positioned to meet these challenges.

Now, let me turn the call over to Caroline, but I will return prior to the question-and-answer period for a few closing remarks.

Thank you, Ralph, and good morning, everyone. I will review our quarterly operating earnings as well as the outlook for full-year results by subsidiary company.

As Ralph said, PSEG reported operating earnings for the third quarter of 2010 of $1.06 per share versus operating earnings of $0.92 per share in last year’s third quarter. Slide four provides a reconciliation of operating income to income from continuing operations and net income for the quarter.

As you can see on slide nine, PSEG Power continues to provide the largest contribution to earnings. Power reported operating earnings of $0.70 per share compared with $0.71 per share last year.

PSE&G reported operating earnings of $0.30 per share compared with $0.17 per share last year and Energy Holdings reported operated earnings of $0.5 per share compared with a negligible contribution to earnings a year-ago. The parent company reported earnings of $0.01 a share this year compared with earnings of $0.04 per share a year-ago.

We provided as always the waterfall charts on slides 11 and 12 that take you through the net changes in quarter-over-quarter and year-to-date operating earnings by business. And I’ll now go through each company in more detail starting with Power.

As shown on slide 14, PSEG Power reported operating earnings for the quarter of $0.70 per share compared with $0.71 per share a year-ago. The operating environment in the quarter benefited from extremely warm weather as Ralph mentioned, a sharp contrast to the operating environment of a year-ago.

A 10% increase in generation volume at spark spreads during the quarter, improved Power’s earnings by $0.04 per share. While we had a 10% increase in generation during the quarter, the improvement came primarily from Power’s coal and gas units.

A 17-day unplanned outage at the Salem-1 unit which you may recall we mentioned in the July call reduced generation from the nuclear fleet during the quarter and reduced earnings by $0.03 per share. So given the different field mix and the cost of the outage combined, the increase in output resulted in a net increase in earnings of $0.01 per share.

While we’ve realized the benefit from the net increase in generation, the price received for base load generation declined as a result of lower contract hedge prices versus prior year. This reduced Power’s earnings by $0.04 per share.

We can also see that weather had a positive effect on BGS load, adding $0.03 per share to earnings. Slightly offsetting this was the reduction to BJS results based on the impact of migration which hurt Power’s earnings by $0.01 a share.

The impact of migration during the quarter was in line with our revised forecast. We estimate that approximately 22% to 24% of the load supplied through BGS migrated to other suppliers at the end of September, but we don’t have the final September data yet.

This is approximately steady with the level we saw as you may recall at the end of the second quarter. Our forecast assumes further erosion in margin of $0.01 per share in the fourth quarter which is consistent with the upper end of our prior guidance of a $0.02-$0.04 per share impact of migration for the full year versus 2009.

We’re now forecasting about $0.04. Market prices for energy remained lower than the embedded price for energy in the BGS contract, and this dynamic has led to the entry of new retail suppliers into the market.

For your modeling purposes, while we don’t specifically forecast migration, keep in mind that each 5% of customer migration from BGS would reduce Power’s earnings by about $0.015 per share on an annualized basis at current prices. In addition, the continued erosion in margin on certain wholesale electric energy supply contracts reduced earnings by $0.02 per share.

Recall that these contracts are marked-to-market. Also realized gains on investments in the Rabi Trust Fund added $0.01 per share to Power’s earnings.

And the decline in the effective tax rate aided earnings by about $0.01 a share. The increase in volume from the fossil fleet and lower average prices resulted in gross margins for the quarter at $57 per megawatt hour compared with $64 per megawatt hour during the third quarter of 2009.

Power’s gross margins were significantly influenced by an increase in generation from its coal-fired fleet and a higher cost of fuel given the outage at Salem-1 versus year-ago levels. Generation from the coal-fired fleet increased 40% during the quarter versus last year in response to weather related demand and an improvement in dark spreads from the levels experienced earlier in the year.

The combined cycle fleet also benefited from market opportunities with an 11% increase in generation versus last year and operated at an average capacity factor of 59% in the quarter. The increase in coal-fired generation for the quarter and year-to-date has reduced our inventory of coal.

We’ve also exercised the flexibility that exists in our contracts to reduce delivery of coal and the completion of the backend technology work at Hudson and Mercer this quarter will provide greater flexibility with regard to our coal supply by reducing the need for the low sulfur Indonesian coal burned at Hudson in 2011 when the BET is expected to go into service. Our coal supply needs over the intermediate term will be lower than historical requirements.

Continued weakness in forward dark spreads is expected to reduce coal-fired generation for 2011 to about 8 terawatt to 9 terawatt hours. Our reduction in output has effectively lengthened our supply.

Re-contracting an existing supply should be sufficient at this point to meet 2011’s coal requirements. Power’s operating earnings for 2010 are still forecast at $1.060 billion to $1.135 billion compared to operating earnings for 2009 of $1.205 billion.

Full-year operating earnings will be affected by continued lower energy pricing. Power continues to hedge its expected generation in future years consistent with past practice.

At the end of September, approximately 68% of Power’s anticipated coal and nuclear generation for 2011 is hedged at an average price of $71 per megawatt hour. This compares with an average hedged price for energy in 2010 of $72 per megawatt hour.

These hedges reflect a PJM West Forward Energy price embedded in BGS of $70 per megawatt hour in 2008, $57 per megawatt hour in 2009, and $50 per megawatt hour in 2010. And as you know the current PJM West Forward prices are in the approximate $40 per megawatt hour range today.

These figures don’t reflect the potential impact of increase bubbles of customer migration, which could reduce the level of power supplied under existing BGS contracts. As I just mentioned, incremental migration equal to about 5% of customer load would reduce earnings by $0.015 per share.

If you run out the math, an additional loss of about 15% of load would reduce our averaged hedged price in 2011 to about $67 per megawatt hour. Now let’s turn to PSE&G.

PSE&G reported operating earnings for the third quarter of 2010 of $0.30 per share compared with $0.17 per share for the third quarter of 2009 as shown on slide 22. PSE&G’s results were influenced by the electric and gas rate relief effective in June and July of 2010 respectively, which improved earnings by $0.05 per share.

And earnings also benefited from a return on the capital invested in the capital stimulus, energy efficiency and solar investment programs approved in 2009 by the Board of Public Utilities. And these programs added about $0.01 per share to earnings.

As Ralph mentioned, New Jersey experienced the hottest summer on record in 2010. And we estimate an increase in weather related demand added about $0.03 per share to earnings.

An increase in transmission revenues effective at the start of the year added $0.01 per share to earnings this quarter. A decline in operating and maintenance expense during the quarter improved earnings by $0.02 per share and realized gains on investments in the Rabbi Trust also added $0.02 per share to the utilities’ earnings, and a decline in the effective tax rate added about $0.01 per share.

These items more than offset an increase in depreciation and interest expense associated with higher levels of capital investment which together reduced earnings by about $0.02 per share. PSE&G’s operating earnings for 2010 are forecast at $425 million to $455 million, the same as our prior guidance, compared with 2009’s operating earnings of $321 million.

Operating earnings will be influenced by a full year of return on capital projects approved by the BPU in 2009, the June and July 2010 increases in electric and gas distribution rates, an increase in transmission rates, a forecast decline in operating and maintenance expenses, and the weather related impact on sales. We’ve updated PSE&G’s capital budget for 2010 to 2012, and we’re providing you with our initial forecast of PSE&G’s 2013 capital expenditures.

PSE&G’s revised budget for 2010 to 2012 calls for capital expenditures of $4.5 billion with plans to spend $1.6 billion in 2013, bringing the capital budget for this four-year period to approximately $6.1 billion. And on slide 25, you can see a breakdown of the spending by category and by year.

This revised capital program recognizes the two-year delay in the in-service date of the Susquehanna-Roseland transmission line, the reconfiguration and delay in operation of the Branchburg-Roseland-Hudson transmission project, and the reduction in distribution spending. In fact, distribution spending is lower by about $425 million through 2012 versus the prior guidance we gave you earlier in the year.

This should increase the proportion of our expenditures that earn a contemporaneous return. For example, transmission related capital spending now represents $3.1 billion or about 50% of the capital budget for the four-year period.

Of course, the number of these transmission projects depend upon our receipt of all the necessary approvals. At the end of 2013, PSE&G’s investment in transmission would represent about 31% of its consolidated rate base.

Distribution related capital spending is forecast at $2.2 billion for 2010 to 2013. Future capital spending on distribution is aligned with forecast levels of depreciation to support earning our authorized return.

PSE&G’s investment program is expected to result in annual rate base growth of about 9.5% per year over this period. Supportive regulatory recovery mechanisms and a constant focus on cost control should support PSE&G’s earning us authorized return with growth in capital providing for growth in PSE&G’s earnings.

For the past 12-month period, PSE&G’s distribution ROE was 9.5%, reflecting only one quarter of results since the completion of the rate case. Now, I’ll turn to PSEG Energy Holdings.

Energy Holdings reported operated earnings of $24 million or $0.05 per share for the third quarter of 2010 versus an operating loss of $1 million during the third quarter of 2009. Operating earnings benefited from the successful termination of two cross-border leases during the quarter, which resulted in a gain of $0.03 per share, which matched a similar level of termination related gains recorded in the year-ago quarter, and results also benefited from the absence of a premium paid on the debt exchange with Power of $0.04 per share, as well as a decline in interest expense of $0.01 per share.

The successful termination of the two cross-border leases during the quarter reduced Holdings’ potential net cash exposure to $330 million on this issue at the end of September. And recall that Holdings has $320 million on deposit with the IRS to defray potential interest cost associated with this issue.

Holdings’ operating earnings for 2010 are forecast at $30 million to $40 million compared to 2009’s operating earnings of $43 million. The loss of income on terminated leases and a reduction in gains from the termination of leases will be partially offset by lower financing costs and tax benefits from the startup of solar projects in Ohio and Florida.

Finally, few other items. PSEG Power indicated during the quarter that is exploring the potential sale of our two 1,000 megawatt each combined cycle generation facilities in Texas through an auction process.

The sale is dependent upon the receipt of offers that we feel reflect the appropriate value for the assets. And should we decide to sell, the schedule would call for closing to occur during the first quarter of 2011.

Finally, just to note, we completed several transactions during the quarter at PSE&G to finance its capital program and refinance high cost debt. We issued $250 million of 10-year paper at 3.5% and refinanced a $100 million of 6.4% tax exempt bonds with the issuance of tax exempt paper as multimode or annual put bonds with an initial term rate of 1.2%.

Holdings recently announced its intention to call debt in December 2010 for the redemption of the remaining $127 million of outstanding principal balance of its 8.5% senior notes that are due in June 2011. Those conclude my remarks and comments on some of our financings.

I’d now like to turn the call back to Ralph for some final comments before of course we open the call up to your questions.

Thanks Caroline. A few points to highlight.

In conversations with many of you we have heard concern expressed about transmission and we’ve heard concern about migration and the impact on Power’s margins. We hope that we’ve answered your questions surrounding transmission.

Now, while it isn’t easy to build these lines, we’re committed to investing in the projects that will improve the reliability of our system, and as you can see it remains the single largest capital program for PSE&G. We’ve also provided you with some guidance around the potential impact of migration on our results.

While we’re not pleased with the associated loss of margin, the more fundamental concern is the forward price of natural gas and its effect on electricity prices. And candidly we’re pleased to see some of you have addressed this issue in your forecast.

Now, while we aren’t immune to declining prices, we are working to mitigate the impact through cost control where we can and through growth investment. So now we’ll open up the lines for your questions.

Yes, on the increase in transmission CapEx, could you guys talk a little more about how much of that spending has been I guess walked down through the approval process, and what major projects we need to follow to deliver or convert the planned CapEx under real spending?

Dan, there is multiple approval processes. So it starts with designation by PJM that is in the RTEP, the Regional Transmission Expansion Plan, and it’s safe to conclude that all of these projects are in the RTEP in all of this expenditure level.

Then there is the rate treatment at FERC. And as you know we have a macro level formula rate treatment at FERC, some of the projects receive a different level of formula rate treatment, incentive adders, construction work-in-progress.

We’ve received that – those two for Susquehanna-Roseland. We had received that for Branchburg-Roseland-Hudson when it was 500-kilovolt project.

Now that’s has been redone, we’re back at FERC to talk to them about the returns and that will be granted. As you see, as I go down this path of what approvals you need, the path gets wider and wider with many more branches and tributaries off of it.

The widest set of branches and tributaries are of course the environmental approvals and the sighting approvals, which I just don’t have the information on my fingertips about what each of these projects are still lacking. Clearly for Susquehanna-Roseland as we’ve disclosed in the past, we’re working with the National Park Service towards a 2012 approval date there.

I guess to put them in the capital budget you guys have a higher level of confidence on conversion as the portfolio is laid out today or how does that level of confidence would have been a year-ago?

Higher for a simple reason that – well, first of all, we made a lot of progress on SR, and we now know what the obstacles are, and that’s resulted in delay. But probably more importantly all the other projects are 230 KV and below and many of them are underground, and they don’t engender the kind of sighting opposition that 500 KV aboveground project’s engender.

Okay. And so how many of these are kind of big profile lines relative to your small $50 million, $100 million investment type of projects?

It depends on how you define big in profile. I would say that 500 KV is the one that attracts the greatest attention and that would be Susquehanna-Roseland.

Now the next step below that is 230 KV for our system that’s Branchburg-Roseland-Hudson. But that’s – a large part of that is an underground construction.

So an underground tends to not attract the same amount of concern, because it’s underground. I’m sorry, I didn’t know how else to complete that sentence.

So, I’d say the one that’s still the primary focus of attention is Susquehanna-Roseland.

Dan, this is Caroline. Just one other thought as you look at the numbers here and think about the modeling of our spend.

One of the things to keep in mind as you know the in-service states for Susquehanna-Roseland and Branchburg-Roseland-Hudson were delayed as we said. So in these numbers that we included on slide 25 just for your information, for Susquehanna-Roseland we estimate that about $550 million of the total of up to $750 million is in the numbers through 2013 and for Branchburg-Roseland-Hudson about $250 million to $275 million of the total of $700 million is in the numbers through 2013.

So there is some spend as you would expect on these projects as outside our forecast period to 2013 given their in-service date. So if you look at those two big amounts and you look at this CapEx for transmission, just so you can keep the time and proportionality that might be helpful.

Okay and not to upset Kathleen but just to clarify one last question. All this transmission CapEx you assume is going to get (inaudible) or is there going to be a subset that wouldn’t because they’re not discreet rate making –

That’s right. All of this transmission gets formula rate treatment just the big projects gets seawhip [ph] and right now the only one that’s approved for seawhip [ph] is SR.

So the logic being of course that the smaller projects go in service much more quickly, so the formula rate treatment gets you as closer to contemporary returns for fields they need to get you.

Thank you good morning.

Good morning.

Everything you’ve articulated is crystal clear. But there was one thing I wanted a little more color on.

If possible you talked about in the first whole paragraph in the press release on PSE&G Power a $0.02 decline in earnings associated wholesale electricity energy supply contracts that you supply from the market. Can you go into a little more detail on what that activity is and what the sort of aggregate contribution is if possible?

Sure Greg, thanks for the question. Yes, so we’ve talked about some of these before and these are low transactions that we bid on that – in most parts low transactions that we bid on, whose power we supply through the market.

And so because they’re not supplied from our assets we treat these on a marked-to-market basis. And so every quarter we’re marking both sides of that transaction to market and we’re putting any changes in that through the P&L.

So the primary driver of what you see here in the $0.02 is really a function of the same dynamics that are going on in the base business and that is in these low contracts there is still opportunity for migration out of those types of contracts by the provider. And so, as migration is expected or experienced and then we forecast it going forward to a large extent based on the experience that we have, we reduce the value of those contracts in terms of what they would return to the company and therefore we take that mark because they’re marked-to-market directly in our earnings as we update those forecasts.

So think of this as marked-to-market, it’s not cash but it’s the representation – our best representation of the change in value of those contracts primarily driven by the same thing we talk about in the base business which is the migration out of these full requirements polar like contracts.

And are those customers also concentrated in New Jersey or you – are those customers in the larger PJM market?

In the PJM market, (inaudible) but not New Jersey?

And do you have an estimate of what the expected contribution from that business is in terms of the total group gross margin outlook for 2010?

Sure. Keep in mind and I am glad you asked that because we do fold this out on a quarterly basis to show you the marked-to-market but it is less than 1%.

So it actually a very small piece of our business.

Basically I would – just wanted to sort of touch base on the Texas sale, what should we think about being the potential size of these proceeds and what’s your expectation might be to deal with the proceeds, meaning in terms of what you might – what the use of proceeds might be?

We are right and you can respect – in fact, we are right in the middle of a sales process now. So we couldn’t even come close remarking on that question in terms of what we expect the size of proceeds.

In terms of the use of proceeds, if we sell and we are exploring the sales that we are not sure, we think we have some good opportunities to deploy capital – those surprises in there, it’s what you have been hearing from us and we have a large capital program and utility with a nearly 10% CAGR associated with it and there is some opportunities perhaps revisit some of those programs and expand them. Our infrastructure is not getting any younger and we have found some opportunities in Holdings with some attractive terms and conditions with creditworthy counterparties with new PPAs on the renewable side.

We have some peakers we are building in Power, some upgrades in our nuclear plants that we are looking at that are now within the planning horizon. So we think we have some good opportunities in our core business to deploy that capital, if we have to.

Okay. And then the lease that’s remaining, I guess you got one lease remaining, is that correct?

That’s correct.

How should we think about the impact, I mean of – what you guys might do with it and would it happen this year and what would that suggest would be the impact in 2011?

Do you want to buy it, Paul?

I don’t think so.

Sure. So we only have one lease remaining.

In terms of how to think about it, as you know from what we have been talking about over the past year, the team’s been working hard to terminate these leases at appropriate term. So as you think about all the leases that we terminated, what’s essentially happened is we reduced our tax liability essentially by the cash received from the counterparties coming in and going out.

So if the terms are appropriate, we would look to terminate this last lease but of course, we have to talk to the counterparties if not we keep the lease. One thing to keep in mind though that the termination of the lease, where we are with the IRS, those two things can continue to happen and dependent of each other to some extent.

You will have to terminate all your leases to try to have the settlement with the IRS given what we have now our exposure on a total basis is about $330 million and we are continuing to having discussions with the IRS to see if we can come to terms. We will try to do that at the same time, we will continue to try to terminate this lease.

So you can really, one is not dependent on the other, you can really pursue both paths and that’s exactly what we are doing. Given the size of the remaining lease though in terms of its impact to earnings, it will be marginal in terms of what might happen either from its earnings proceeds next year or a termination as you know we have two leases this quarter (inaudible).

So it’s really a small number and I think it’s a credit and I think it’s a credit to the team’s work to really bring us down to only lease less.

(Inaudible) that 330 exposure, this 320 on deposit.

Correct, correct.

When we are thinking about – I mean is it likely that I guess we won’t see much of any of this activity in 2011?

That’s right because there is only one left. So it would either be terminated or it’s the last one left.

I guess I am a little surprised in terms of use of proceeds, not to hear possible repurchase as an option particularly given the fact that the company has gotten the balance sheet to where you want it to be. So I guess I would be curious to hear why you wouldn’t consider using at least a portion for share repurchase?

Thank you by the way for recognizing the condition of the balance sheet, we are proud of that, we worked hard for four years now at least to get it to where it is and we are pleased with that condition. Most of our long investors tell us, look, we look that you find good ways to deploy capital and if you can get attractive risk adjusted returns, then we want you to use it in that way.

So we are obviously disclosing to you the things that we have a high degree of confidence we can invest in. What I was trying to say earlier to Paul was that there are many things like that we consider all the time, some of them we shred the paper and say, no, that one didn’t pan up to where we want.

But there are others that are percolating that all organic in nature that we like and we think we can put that money to good use. So I would rather grow the business with attractive risk adjusted returns and create a positive MVP investment for our shareholders than something that just as a zero MVP.

As a follow-up, there were a number of unresolved issues in the rate cases that were supposed to be dealt with in separate proceedings. Have those proceedings started?

And can you just give us an idea of where you are on those issues?

So there were two issues in particular. One related to a tariff rate, a tower had pertaining to gas purchases, I guess we’re about to disclose in the Q, so I shouldn’t run that where that stands but we have been in settlement discussions and we’ll have a little bit more color on that in the Q, sufficed to say that there was a prior published date of October 25th when the hearings would take place and you can go to the BP (ph) website to see that those hearings have not taken plane and derive your own conclusions from that.

The second issue is on consolidated taxes and there have been series of extensions that have been granted to us to file for a full blown proceeding on consolidated tractions. And how those are applied not just to us but to all utilities in New Jersey inclusive of water utilities and gas utilities.

So that’s still in the regulatory calendar being pushed off a bit.

And keep in mind as we’ve said before on consolidated taxes, should any proceeding result come to any conclusion about consolidated tax adjustments, that would prospective only and there would be no impact on the rate case that we just settled.

Okay. And then I was curious on your coal cost per megawatt hour.

There is like a 10% reduction if I compare this quarter to a year ago quarter. Can – what accounts for that saving?

Sure, so Paul as I mentioned we are burning more coal, right. So as we burn more coal, we bring the inventory down and some of the higher price inventory comes off and we have lower price inventory that we’re burning.

Also keep in mind we talked about earlier this year, that the price of our Adaro (ph) coal relative to last year also came down. So that really moderated our coal costs overall.

As we burned more, it broke down the inventories and had some lower price coal from Adaro.

Great. I think that’s it.

Thank you very much.

Thanks Paul.

Good morning.

Good morning Jonathan.

Two questions, the first one relates to the distributions, capital spend. I think I had you right that it’s down $425 million from what you had given before.

If I remember right, the $140 million of that you communicated at the Q two stage.

Yes.

I wanted just to check that number is that is the $425 million is, I don’t know, incremental for the 140?

The 425 is obtained by 140 and multiplying by three and rounding.

Okay, I see. And can you – so the one, it’s not an incremental?

No.

No, no.

The 140 was an annual number?

Correct.

Okay, and the 425 is over the three years.

Right. And in fact if you just, notice on our page 25 we get the number out 320.13.

So while the 425 is 140 times three when you look at this page, you should know that in our planning, we plan that distribution spend at a $140 million lower each year over the entire period. We’re just reconciling to our prior numbers here.

Okay, I got it. And is that 400ish million number of 12 and 13 shakeout, is that a reasonable run rate or you still doing things out under which is somewhat one off in nature?

Yes that is our kind of normal run rate for matching our maintenance CapEx through our depreciation so we can achieve our loud return.

Okay.

So in the earlier years are driven by the stimulus funding that we had received approval for 2009.

And then on the same slide you have this obviously the drop off in the renewable slide. Is the $30 million number in 13, should we think about it as just something you have left visibility on what you’re likely to be doing out in that timeframe or its.

Jonathan, that’s one tough to predict, as you know the stage is now revisiting its energy master plan and I suspect the entire 20% renewables – it’s not exactly 20% but it’s close to that by 2020, it will be something that will come under review. At these CapEx numbers for renewables we are nowhere near the run rate required lots of r’s in there, run rate required to achieve that 20% by 2020.

So I think we’ll get a little greater clarity at the end of this year first quarter next year in terms of how aggressive the state wants to be for the next decade and that will influence 13 and beyond.

Okay, great. Thank you.

And if I could just on one other topic, I want to make sure I understand this the sensitivities you gave on migration. Its 5% incremental migration in ‘011 would be about $1.05 per share hit, but then you talked about 15% in terms of average hedge prices.

Was that an 15% beyond the 5% so 20 in total. I think the release said one thing and then seemed to say something slightly different in the prepared remarks.

Right, thanks Jonathan, just to clarify, just to give you some pieces of the math maybe just to help you to think that through. In terms of the $1.05.

So if you think about what our coal and nuclear output, let me just walk you down this a little bit because that may help. That 50% of our coal and nuclear output, in total, coal and nuclear is about 40 terawatt hours a year.

So half of its about 20 terawatt hours. With the migration we’ve already seen in BGS.

BGS is about 15 terawatt hours. It used to be half and now it’s less than that because of the migration.

So if you take 5% of the 15 terawatt hours and you multiply that out by the Delta in the embedded PJM West price in the BGS contract with the current level of PJM West price. And you rollout that math, you’ll get about a penny and a half.

So that’s how we came up with a penny and a half. The 67 that the change in the hedge price was simply running that same sort of thinking and that same sort of calculation by taking that out of the hedged amount that we have pulling that migrating BGS load out of the hedged amount and then recalculating the weighted average hedge prices of portfolio, keeping in mind that the BGS hedge price has more things in it besides just the energy.

All those things we’ve talked about in our bar chart relative to the PJM West hedge which would not have hedge things like pieces in it. So you have just do those, that math in two pieces.

So one is about how to do the penny per share, the other is weighted average of our hedge portfolio average price.

So that 15% would be sort of on top of 5%, so really 20%?

No, no.

No.

What we’re trying to give you sort of a rule of thumb way to think of migration, you can easily think of the rule of thumb in terms of EPS impact, or you can think of the rule of thumb in terms of.

Okay.

Gross margin impact.

So it’s a difference sense them.

Yes unfortunately we gave you two different thumbs. We gave you 5% thumb and a 15% thumb.

Yes.

Thank you sir.

So I would just make sure they were separate. Just finally on that topic, is it reasonable to assume given that switching showed up during the course of this year that there will be another $0.04 or so if carryon into ‘011 from ‘010.

So we haven’t – as you know we’re not forecasting ‘011. So it’s too soon to know as we pointed out, we do have obviously retailers outlooking for residential switching.

We don’t know the success of that yet, so we’re not really sure. One think I’d just add is keep in mind we saw levels of migration appear to be similar at the end of this quarter to where they were last quarter, but you also have to keep in mind that that’s always a function of that headroom calculation as we call it.

And with the hot weather and the spike in prices, you saw headroom actually go the other way. Remember last year in the summer we talked about it being very high.

This year the summer was very low because of the spike in prices. So when we come back to a more normal condition and then with what’s happening with residential, it’s too early to really forecast what that would be.

Thank you very much.

Sure.

Hi, actually you hit the topic I just wanted to clarify on. But do you – what was the number percent of load that migrated this year?

Was it – are you saying that it basically there wasn’t any incremental migration?

No.

So it started out in 19% – 18% 19% and it’s now at about 24% at the end of third quarter. It was also about 24% at the end of second quarter.

That’s right.

Okay, so 24% and the 20 – the 15 terawatt hours is what it is now after the 24% has left?

Correct, correct.

And when you talk about the 5% sensitivity that’s off to 15 terawatt hours, so that’s half of where we are today not where below it used to be.

That’s correct. It’s also up of the comparison between the prices in BGS and the prices today.

So you have to be careful when you look at the percentage migration like last year and try to say it should be same number because you have to compare the embedded PJM West price to the market prices.

Right.

Last year. So what we’re trying to do is keep current, right.

That current migration amount, the current terawatt hours and a current estimate of what the loss would be for an incremental percentage point or five percentage points of migration given the current Delta.

And we generally assume that you’ve resell that power just into the kind of around the clock wholesale power market in PJM. Is that the right way to look at it?

So for the most part yes Steve, but we’ll also try to aggregate a full requirements product or bundle of products for TPS is Third Part Suppliers. So we – as Caroline said our generation output is up.

It’s just the price we’re getting for is different depending on whether we’re selling it through BGS or selling it into the market or selling it through bilateral arrangements to third party supplier.

And we’re doing as Ralph said, we’re doing some of those products like a fixed load shape for example but we’re not going to take full requirements risk on the things that already migrated out and taken for requirements risk over again.

Okay, and then with respect to, Ralph you mention O&M savings and with pricing coming down managing cost, is that something where we should think about maybe generation O&M being flattish so you offset growth or is it something where it’s possible that it could come down going forward?

No I would, I think I would stay with the numbers that Caroline and Kathleen and I have been showing you now for probably a year in terms of the CAGR for the company.

Okay.

That’s not easy work Steve, I’m not looking for sympathy but.

Right.

Our hands are full just getting there.

Right, and that’s about half a percentage, we’ve been forecasting CAGR.

Okay, and then one last popular topic on the – just on from a credit standpoint. Where is roughly the FFO to debt at PEG Power either now or when you look through kind of a down cycle?

Right, so good question Steve. The – as you know as we’ve said before, we target as a floor, not as target but as a floor of 35% FFO to debt for PEG Power.

And as we look at historically where we’ve been, as we look at our forecast, we see ourselves staying comfortably in that range. PEG Power is just a cap – ended this quarter at about 42.5% similar to what has done in prior quarters.

We managed those debt levels to make sure that we keep that – keep the balance trim and we see ourselves being able to sustain that kind of level, 35% as a floor going forward.

Thank you.

Hi good morning. I just wanted to clarify, maybe what percentage of the 24% of switching comes from residential customers versus commercial customers.

And maybe just some color on the switching activities between commercial and residential and how they would differ between the customer classes?

Sure, so on residential customers, we’re seeing almost no switching at this point. So we’ve talked about numbers and that’s like 1% range or so, depending on the particular LDC, you might see something different but we’re still – the numbers are very small, all of what we’ve talked about in terms of the drivers that the incremental hit to our EPS from migration has been in the commercial and industrial.

So we really haven’t seen it as a factor to-date. Keep in mind as you probably know there are folks out there looking to sign up residential customers.

They’re probably stickier than the commercial and industrial but we haven’t seen that yet. So we’ll have to see that going forward.

Okay, and then second. At this point do you believe that east portion of (inaudible) is going to be included in the 2014, 2015 RPM auction or is that going to be delayed till the auction after?

No I think that in general right now the line is being viewed in the totality. And the desire and the part of policy makers in the regent has split really isn’t there, and I think that’s not unreasonable in their part.

People want to see what the National Park Service is going to do.

So would you view it as been into the 2015, 2016 auction or 2014, 2015?

I don’t have the dates straight in my mind, Carol do you know?

Yes, so it’s potentially at the earliest the 15, 16 because the eastern portion is mid 14, western portion is mid 15. So if it doesn’t flip and if it’s on time you might see it then come back to 15, 16.

Great, thank you very much.

Hi, thank you. Good morning.

Just a question on the hedges if I may come back to that subject. Have you been hedging 2012 at power?

Yes, so we have been hedging 2012 at power but very small degree. So the hedges for 2012 for power in about the mid 20% range.

Typically think of as you go out, the markets become obviously less liquid and of course the BGS by nature is being a three year contract puts some percentage outage in 2012, but right now the 2012 hedged amounts are relatively small in that mid 20% range. Remember we tried to put this in ratably so that as you move into a year we move up in the hedge percentages, but right now 2012 is move out that amount.

All right, thank you. And one point of confusion on 2011.

When I look to the prior disclosure on the hedges, I saw a 68% of coal and nuclear output was actually hedged in 2011 at $75. And in the new disclosure I see 68% at $71.

What’s the disconnect there? Why does the percentage hedge remain about the same?

Yes, that’s a good question. I don’t think we gave out that number but I know if you take a ruler on the graph you can get to a number similar to that for the hedged amount.

Yes, so when we provided that disclosure at midyear, we were using the data we had that was a little bit older, what we’ve done now is to update that hedged price or the assumption of the migration amount that we just talked about, the 22% to 24%. So as we updated that and assume that going forward, that pull that average price down even though the hedge percentage is not really that different, the average prices has come down.

We’ve pulled through the hedge, the migration amount, added a little more and hedging that’s how you get back up to about the same hedge percentage. But you’re weighted average math is now a little bit different.

Okay, we may have to discuss this offline. As a quick last question, have you disclosed the amount of O&M and depreciation that’s carved out of the Texas assets?

No.

No we haven’t talked about that in terms of overall profitability. You have to say that they are profitable.

And we did give you in our deck this quarter as we typically do, the margin performance for Texas. So just to point that out on page 19, $41 million in gross margin from the two assets, both plan in the third quarter.

Thank you, that’s very helpful.

Good afternoon. Ralph, the way I look at it is by the time we come to the next BGS auction, this migration risk will go lower because the headroom would have decreased as the average goes down.

Is that a correct assumption?

That’s correct. In theory as BGS approximates the market, there is no room for the SG&A associated with customer acquisition.

So how do you acquire customers.

So in essence as commodity prices – so we are basically what we are doing is we are coming to market with this migration a little bit earlier but then as prices kind of we go to 12 and then go to 13 when capacity kind of picks up, our outlook going in terms of our capacity prices and everything going into 13, that’s not affected. The only thing that is being affected is that we might be coming to trough a little bit earlier that trajectory of the trough is becoming a little bit changing and going a little bit earlier than before.

Is that correct?

That’s correct Ashar. That’s exactly right.

Okay, thank you so much.

Hi I wondered if you could just touch on the CapEx for PEG Power and if that outlook has changed at all. And in particular I believe you might have allocated some CapEx to growth projects and maybe that’s TBD (ph) based on the sale of the Texas generation.

But just wanted to make sure my total CapEx numbers were in the ballpark.

Yes, so thanks Leslie. No we haven’t really changed the numbers for PEG Power.

Keep in mind that we did have some growth spending in there, wouldn’t change because of taxes as the growth spending is essentially things like nuclear up rates at our nuclear at Peach Bottom in particular, and the peakers that we bid in successfully in the last two RPM auctions. They’re the primary drivers of the growth CapEx going forward.

The other thing that we’ve noted a lot and it’s in the table that we put in the cay and still relevant is the decrease in the environmental spending, environmental CapEx because the VETs (ph) are essentially complete at the end of this year. So that number comes down, as you think about that also for going forward keep in mind what that also means is those assets go into service and of course then they start to become depreciated as well.

So that’s essentially the story on power. And it really has not significantly changed.

The peakers and the up rates on the growth capital, the environmental spend winds down. It’s actually part of the reason why we’re able to do what we’re doing which is to fund these utility allow it to grow while still maintaining the balance sheet that we have.

Okay, great. Thanks for clarifying that.

Thanks.

Operator, I think we’ve reached our allotted time unless there is another question.

Yes, we will. Thank you.

Hi guys thank you for taking my question. I was just looking at New Jersey electric switching stats for the various P&D companies.

Noticed that the total amount of load switch for – in the PSEA&G service territory at the end of August was about 31%, but you talked about just the amount of power having seen migration of being 500 or 600 basis points less than that. Just curious, kind of to understand the explanation for what you think maybe driving that Delta?

Remember Michael, BGS is a state wide phenomena.

Sure.

So you have to look at PSE&G, Atlantic Electric and Jersey Central. I don’t have the numbers memorized but I’m pretty sure, Jersey Central and Atlantic have a much larger residential population and therefore they’ll have a smaller amount of switching.

Right, and also.

Got it, okay.

You have to be careful if you’re looking at commercial and industrial mid-size or the CIEP class of load which is essentially out of – migrated out already. So depending on which customer class and within BGS there are customer classes.

You have to be careful when you look at those percentages to come up with the right numbers that you should put in our models when you’re looking at our numbers.

Yes and it seems that the place where acceleration at least through the end of August had really kicked up or at least that it surprised us a little bit, was in the really small commercial side, the sub 500 kilowatt customers, just where the customer account and switching level had picked up pace a bit. How do you compare the profitability of that customer class versus residential?

I’d say for commercial and industrial just looking at the class in the aggregate. So looking at the pieces and then looking at the total, we see commercial and industrial just to see some color on your numbers at about two-third switched in the aggregate out of BGS.

We don’t really do profitability specifically by customer category, but just to give you the round numbers, about two-thirds out of commercial and industrial and as we said only about 1% out of residential.

Got it. Okay, thank you.

Much appreciated.

Sure.

Thank you all. If you do have additional questions, please feel free to call Investor Relations at 973-430-6565, that’s my numbers or provide (inaudible) at 6596.

We appreciate it. Thank you very much for your interest and participation in today’s call.